Systems and methods for producing dimethyl sulfide from sour gas

ABSTRACT

Dimethyl sulfide is produced from sour gas. The dimethyl sulfide is utilized in an oil recovery formulation introduced into a petroleum-bearing formation to enhance recovery of petroleum from the formation.

RELATED CASES

This application claims benefit of U.S. Provisional Application No. 61/839,982, filed on Jun. 27, 2013, which is incorporated herein by reference.

FIELD OF THE INVENTION

The present invention is directed to systems and methods for producing dimethyl sulfide from sour gas.

BACKGROUND OF THE INVENTION

Stringent safety and environmental standards for sulfur emissions, together with low sulfur specifications for petroleum derived products and fuels, have resulted in making hydrogen sulfide and sulfur management in petroleum production operations critical. Petroleum refineries and chemical manufacturers view petroleum with high sulfur content as having lesser value relative to petroleum with low sulfur content. Therefore, petroleum producers may select against production of fluids from reservoirs that have high hydrogen sulfide content and yield produced oils with high sulfur content to meet strict standards for sulfur content in the petroleum sold to the refineries and chemical manufacturers.

To produce petroleum with acceptable sulfur content from formations that include appreciable levels of sulfur, the sulfur compounds, primarily hydrogen sulfide, are typically separated and converted to elemental sulfur, for example, by a Claus process. However, elemental sulfur has a low market value and the separation and conversion process for hydrogen sulfide to sulfur is energy intensive as well as expensive. Consequently, the corresponding petroleum-bearing formations (e.g., subterranean formations having appreciable concentrations of sour gas) are under-produced.

Improved systems and methods for producing petroleum from petroleum-bearing formations containing significant quantities of sour gas are desirable.

SUMMARY OF THE INVENTION

The present invention is directed to systems and methods for producing dimethyl sulfide (sometimes referred to herein as “DMS”) from sour gas and utilizing the produced dimethyl sulfide in an oil recovery formulation to enhance recovery of petroleum from a petroleum-bearing formation.

In one aspect, the present invention is directed to a method comprising:

separating methane and separating hydrogen sulfide from a sour gas comprised of methane and hydrogen sulfide;

producing carbon monoxide and hydrogen from at least a portion of the separated methane;

producing methanol from at least a portion of the produced carbon monoxide and at least a portion of the produced hydrogen;

producing dimethyl sulfide from at least a portion of the produced methanol and at least a portion of the separated hydrogen sulfide;

producing an oil recovery formulation that comprises at least 75 mol % dimethyl sulfide from at least a portion of the produced dimethyl sulfide;

introducing the oil recovery formulation into a petroleum-bearing formation comprising petroleum;

contacting the oil recovery formulation with petroleum in the petroleum-bearing formation; and

subsequent to contacting the oil recovery formulation with petroleum in the petroleum-bearing formation, producing a fluid from the petroleum-bearing formation, wherein the produced fluid comprises at least a portion of the petroleum from the petroleum-bearing formation.

In another aspect, the present invention is directed to a system, comprising:

a first separator structured and arranged to receive a sour gas comprised of methane and hydrogen sulfide, wherein the first separator is structured and arranged to separate methane and hydrogen sulfide from the sour gas;

a methane reactor fluidly operatively coupled to the first separator to receive at least a portion of the separated methane from the first separator, wherein the methane reactor is structured and arranged to produce carbon monoxide and hydrogen from the methane received therein;

a methanol reactor fluidly operatively coupled to the methane reactor to receive carbon monoxide and hydrogen from the methane reactor, wherein the methanol reactor is structured and arranged to produce methanol from the carbon monoxide and hydrogen received therein;

a dimethyl sulfide reactor fluidly operatively coupled to the methanol reactor to receive methanol from the methanol reactor and fluidly operatively coupled to the first separator to receive hydrogen sulfide from the first separator, wherein the dimethyl sulfide reactor is structured and arranged to produce dimethyl sulfide from the methanol and the hydrogen sulfide received therein;

an injecting mechanism fluidly operatively coupled to the dimethyl sulfide reactor to receive dimethyl sulfide from the dimethyl sulfide reactor, wherein the injecting mechanism is structured and arranged to introduce an oil recovery formulation comprised of dimethyl sulfide received from the dimethyl sulfide reactor into a petroleum-bearing formation;

a producing mechanism that is structured and arranged to produce a fluid comprised of petroleum from the petroleum-bearing formation.

The features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of the preferred embodiments that follows.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of the present invention, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, as will occur to those skilled in the art and having the benefit of this disclosure.

FIG. 1 is an illustration of a system in accordance with the present invention.

FIG. 2 is an illustration of a system in accordance with the present invention.

FIG. 3 is an illustration of a portion of a system in accordance with the present invention.

FIG. 4 is an illustration of a portion of a system in accordance with the present invention.

FIG. 5 is an illustration of a portion of a system in accordance with the present invention.

FIG. 6 is a diagram of a well pattern for production of petroleum in accordance with a system and process of the present invention.

FIG. 7 is a graph showing petroleum recovery from oil sands at 30° C. using various solvents.

FIG. 8 is a graph showing petroleum recovery from oil sands at 10° C. using various solvents.

FIG. 9 is a graph showing the viscosity reducing effect of increasing concentrations of dimethyl sulfide on a West African Waxy crude oil.

FIG. 10 is a graph showing the viscosity reducing effect of increasing concentrations of dimethyl sulfide on a Middle Eastern Asphaltic crude oil.

FIG. 11 is a graph showing the viscosity reducing effect of increasing concentrations of dimethyl sulfide on a Canadian Asphaltic crude oil.

DETAILED DESCRIPTION

The present invention is directed to systems and methods for producing dimethyl sulfide from sour gas and utilizing the produced dimethyl sulfide in an oil recovery formulation to enhance recovery of petroleum from a petroleum-bearing formation.

The systems and methods described herein provide for, in some embodiments, production of dimethyl sulfide from sour gas and use of the produced dimethyl sulfide as a solvent in an oil recovery formulation to recover petroleum from a petroleum-bearing formation. As dimethyl sulfide is a highly effective solvent for recovering petroleum from petroleum-bearing formations, the low-value sour gas becomes an attractive, higher-value component of the production stream from a petroleum-bearing formation. Therefore, petroleum-bearing formations that were once considered too sour to economically produce now have a useful outlet for the sour gas.

The high efficacy of the dimethyl sulfide as a petroleum solvent is due, at least in part, to its miscibility with various petroleum compounds (described further herein) and its reduced (if any) reactivity with formation water to further sour the petroleum. That is, other solvents like carbon disulfide that are effective in enhancing the recovery of petroleum from petroleum-bearing formations decompose to yield sulfur-containing compounds that can further sour the reservoir.

Further, in some instances, the production of dimethyl sulfide may be at or proximal to the well-site where the dimethyl sulfide is used for recovering petroleum, which significantly reduces solvent transportation costs associated with solvent enhanced petroleum recovery.

As used herein, the term “at or proximal to the well-site” refers to a location at the well-site to a distance from the well-site suitable for transporting sour gas via pipeline. A suitable distance for transporting sour gas via pipeline may vary by location depending on terrain, engineering requirements and governmental regulations. Typically a suitable distance is within 0 to 1,000 km of the well-site, but may be outside that range, which one of ordinary skill in the art would recognize.

“Petroleum”, as used herein, is defined as a naturally occurring mixture of hydrocarbons, generally in a liquid state, which may also include compounds of sulfur, nitrogen, oxygen, and metals. As used herein, the term “petroleum” encompasses light hydrocarbons and heavy hydrocarbons. As used herein, the term “light petroleum” refers to petroleum having an API gravity of greater than 20°. As used herein, the term “heavy petroleum” refers to petroleum having an API gravity of at most 20°. Unless otherwise specified, as used herein the API gravity is determined in accordance with ASTM Method D4052. The petroleum contained in the petroleum-bearing formation may have a viscosity under formation conditions (in particular, at temperatures within the temperature range of the formation) of at least 1 mPa s (1 cP), or at least 10 mPa s (10 cP), or at least 100 mPa s (100 cP), or at least 1000 mPa s (1000 cP), or at least 10000 mPa s (10000 cP). The petroleum contained in the petroleum-bearing formation may have a viscosity under formation temperature conditions of from 1 to 10000000 mPa s (1 to 10000000 cP). In an embodiment, the petroleum contained in the petroleum-bearing formation may have a viscosity under formation temperature conditions of at least 1000 mPa s (1000 cP), where the viscosity of the petroleum is at least partially, or solely, responsible for immobilizing the petroleum in the formation.

“Miscible”, as used herein, is defined as the capacity of two or more substances, compositions, or liquids to be mixed in any ratio without separation into two or more phases.

“Residue”, as used herein, refers to petroleum components that have a boiling range distribution above 538° C. (1000° F.) at 0.101 MPa, as determined by ASTM Method D7169.

“Fluidly operatively coupled or fluidly operatively connected,” as used herein, defines a connection between two or more elements in which the elements are directly or indirectly connected to allow direct or indirect fluid flow between the elements. The term “fluid flow”, as used in this definition, refers to the flow of a gas or a liquid; the term “direct fluid flow” as used in this definition means that the flow of a liquid or a gas between two defined elements flows directly between the two defined elements; and the term “indirect fluid flow” as used in this definition means that the flow of a liquid or a gas between two defined elements may be directed through one or more additional elements to change one or more aspects of the liquid or gas as the liquid or gas flows between the two defined elements. Aspects of a liquid or a gas that may be changed in indirect fluid flow include physical characteristics, such as the temperature or the pressure of a gas or a liquid; the state of the fluid between a liquid and a gas; and/or the composition of the gas or liquid. “Indirect fluid flow”, as defined herein, excludes changing the composition of the gas or liquid between the two defined elements by chemical reaction, for example, oxidation or reduction of one or more elements of the liquid or gas.

It should be noted that the terms “separate,” “separates,” “separating,” and the like, as used herein, do not necessarily imply a 100% separation. Further, the term “stream” does not necessarily imply a purity level of the composition thereof.

Systems 100, 200, and 300 illustrated in FIGS. 1-3, respectively, are systems in accordance with the present invention that may be utilized for conducting a process in accordance with the present invention. Each of the systems 100, 200, and 300 of FIGS. 1-3, respectively, may be similar in some respects (e.g., similar system components or similar portions of the system may be understood with similar reference numerals).

In some embodiments, producing dimethyl sulfide from a sour gas comprising methane and hydrogen sulfide may involve separating methane and hydrogen sulfide from a sour gas stream; producing carbon monoxide and hydrogen from at least a portion of the separated methane; producing methanol from at least a portion of the produced carbon monoxide and at least a portion of the produced hydrogen; and producing dimethyl sulfide from at least a portion of the produced methanol and at least a portion of the separated hydrogen sulfide.

In some embodiments, producing dimethyl sulfide from a sour gas comprising methane and hydrogen sulfide may involve separating methane and hydrogen sulfide from a sour gas; producing carbon monoxide and hydrogen from at least a portion of the separated methane; producing methanol from a portion of the produced carbon monoxide and a portion of the produced hydrogen; producing methanethiol from a portion of the produced carbon monoxide, a portion of the produced hydrogen, and at least a portion of the separated hydrogen sulfide; and producing dimethyl sulfide from at least a portion of the produced methanol and at least a portion of the produced methanethiol.

An oil recovery formulation is produced with at least a portion of the produced dimethyl sulfide. In some instances, the oil recovery formulation may comprise at least about 75 mol. % dimethyl sulfide, where some or all of the dimethyl sulfide is the produced dimethyl sulfide. In some instances, the oil recovery formulation may comprise at least 80 mol. %, or at least 85 mol. %, or at least 90 mol. %, or at least 95 mol. %, or at least 97 mol. %, or at least 99 mol. % dimethyl sulfide, where some or all of the dimethyl sulfide is the produced dimethyl sulfide. In some instances, the oil recovery formulation may consist essentially of dimethyl sulfide, or may consist of dimethyl sulfide.

In some instances, the oil recovery formulation may comprise dimethyl sulfide and one or more co-solvents. The one or more co-solvents are preferably miscible with dimethyl sulfide. Examples of suitable co-solvents may include, but are not limited to, o-xylene, toluene, carbon disulfide, dichloromethane, trichloromethane, C3-C8 aliphatic and aromatic hydrocarbons, natural gas condensates, hydrogen sulfide, diesel, kerosene, dimethyl ether, decant oil, and mixtures thereof. In some embodiments, water is absent from the oil recovery formulation (i.e., no additional water than residual water concentrations in the components of the oil recovery formulation under ambient conditions).

In some instances, the oil recovery formulation described herein preferably is relatively non-toxic or is non-toxic. The oil recovery formulation may have an aquatic toxicity of LC50 (rainbow trout) greater than 200 mg/l at 96 hours. The oil recovery formulation may have an acute oral toxicity of LD50 (mouse and rat) of from 535 mg/kg to 3700 mg/kg, an acute dermal toxicity of LD50 (rabbit) of greater 5000 mg/kg, and an acute inhalation toxicity of LC50 (rat) of at least 40250 ppm at 4 hours.

In some instances, the oil recovery formulation described herein preferably has a relatively low density (e.g., at most 0.9 g/cm3, or at most 0.85 g/cm3).

In some instances, the oil recovery formulation described herein may have a relatively high cohesive energy density (e.g., from 300 Pa to 410 Pa, or from 320 Pa to 400 Pa).

Some embodiments may further involve introducing the oil recovery formulation into a petroleum-bearing formation comprising petroleum; contacting the oil recovery formulation with petroleum in the petroleum-bearing formation; and producing a fluid from the petroleum-bearing formation, wherein the produced fluid comprises at least some of the petroleum from the petroleum-bearing formation. In some instances, the produced fluid may also comprise dimethyl sulfide. In some instances, the produced fluid may also comprise sour gas that is comprised of methane and hydrogen sulfide.

Referring now to FIG. 1 illustrating an exemplary system of the present invention, a system 100 includes a first separator 102 structured and arranged to receive a sour gas comprised of methane and hydrogen sulfide, for example via conduit 104. The first separator 102 is structured and arranged to separate methane and to separate hydrogen sulfide from the sour gas. A methane reactor 110 is fluidly operatively coupled to the first separator 102, for example via conduit 106, to receive at least a portion of the separated methane from the first separator. The methane reactor 110 is structured and arranged to produce carbon monoxide and hydrogen from the methane received therein. A methanol reactor 116 is fluidly operatively coupled to the methane reactor 110 to receive carbon monoxide and hydrogen from the methane reactor, for example via conduits 112 and 114, respectively. The methanol reactor 116 is structured and arranged to produce methanol from the carbon monoxide and hydrogen received therein. A dimethyl sulfide reactor 120 is fluidly operatively coupled to the methanol reactor 116 to receive methanol from the methanol reactor, for example via conduit 118, and is fluidly operatively coupled to the first separator 102 to receive hydrogen sulfide from the first separator, for example via conduit 108. The dimethyl sulfide reactor 120 is structured and arranged to produce dimethyl sulfide from the methanol and the hydrogen sulfide received therein. The system further includes an injecting mechanism 124 that is structured and arranged to introduce an oil recovery formulation comprising dimethyl sulfide into a petroleum-bearing formation 126, and a producing mechanism 128 that is structured and arranged to produce a fluid comprising petroleum from the petroleum-bearing formation after introduction of the oil recovery formulation into the formation. The injecting mechanism 124 is fluidly operatively coupled to the dimethyl sulfide reactor 120 to receive at least a portion of the dimethyl sulfide from the dimethyl sulfide reactor, for example via conduit 122, where the dimethyl sulfide received in the injecting mechanism is the oil recovery formulation, or is incorporated into the oil recovery formulation, or has been incorporated into the oil recovery formulation. The producing mechanism may produce fluid comprising petroleum from the formation through conduit 130. The injecting and producing mechanisms 124 and 128, respectively, and the petroleum-bearing formation 126 are discussed further herein.

Regarding the first separator 102, one of ordinary skill in the art, with the benefit of this disclosure, should recognize conventional methods and systems/apparatuses capable of separating methane and hydrogen sulfide from sour gas. For example, the first separator 102 may be a liquid absorber or a wet scrubber utilizing a chemical solvent such as an amine, for example N-methyl-diethanol amine (MDEA), to selectively absorb H2S from the sour gas and separate the methane from H2S, or utilizing a physical solvent such as methanol or a methanol/water mixture comprising at least 50 wt. % methanol at a temperature of below −40° C., or the dimethyl ether of polyethylene glycol (DEPG) at a temperature from −18° C. to 175° C., or N-methyl-2-pyrrolidone (NMP) at a temperature of −5° C. to 25° C., or propylene carbonate (PC) at a temperature of −20° C. to 65° C., to selectively absorb H2S from the sour gas. The absorbed H2S may be released from the absorbing liquid separate from the separated methane by heating the absorbing liquid above the temperature at which the liquid absorbs H2S to release the H2S as an off-gas.

Regarding the methane reactor 110, one of ordinary skill in the art, with the benefit of this disclosure, should recognize conventional methods and systems/apparatuses capable of producing carbon monoxide and hydrogen from methane according to at least one of the reactions CH4+½O2→CO+2H2; CH4+H2O→CO+3H2; 2CH4+O2+CO2→3H2+3CO+H2O; or 4CH4+O2+2H2O→10H2+4CO. For example, carbon monoxide and hydrogen may be produced from methane utilizing an autothermal reformer, a steam methane reformer, a catalytic partial oxidation reactor, a partial oxidation reactor, and the like.

Regarding the methanol reactor 116, one of ordinary skill in the art, with the benefit of this disclosure, should recognize conventional methods and systems/apparatuses capable of producing methanol from carbon monoxide and hydrogen according to the reaction CO+2H2⇄CH3OH. For example, methanol reactors may utilize catalysts including a mixture of copper, zinc oxide, and alumina (Cu/ZnO/Al2O3) at a pressure of about 5 MPa to about 10 MPa and at a temperature of from 200° C. to 300° C. to produce methanol from carbon monoxide and hydrogen.

Regarding the dimethyl sulfide reactor 120, one of ordinary skill in the art, with the benefit of this disclosure, should recognize conventional methods and systems/apparatuses capable of producing dimethyl sulfide from methanol and hydrogen sulfide according to the reaction 2CH3OH+H2S→DMS+2H2O. For example, the dimethyl sulfide reactor may utilize a solid acid catalyst having moderate acidity, for example a La2O3/Al2O3, γ-Al2O3, or WO3/ZrO2 catalyst, for producing dimethyl sulfide from methanol and hydrogen sulfide at a temperature of from 320° C. to 420° C. It should be noted that the production of dimethyl sulfide may advantageously include an excess of the stoichiometric amount of methanol used to produce dimethyl sulfide to minimize incomplete reaction that can yield significant quantities of methanethiol in the dimethyl sulfide product, for example methanol may be provided to the DMS reactor at a molar ratio of from 2.1:1 to 4:1 relative to the hydrogen sulfide provided to the DMS reactor. Unlike dimethyl sulfide, methanethiol is reactive and toxic, and is preferably not produced in appreciable quantities in the methods described herein. In some instances, a recycle loop may be included to mitigate the production of methanethiol in appreciable quantities.

Referring now to FIG. 2 illustrating an exemplary system of the present invention, a system 200 includes a first separator 102 structured and arranged to receive sour gas comprised of methane and hydrogen sulfide, for example via conduit 104. The first separator 102 is structured and arranged separate methane and to separate hydrogen sulfide from the sour gas. A methane reactor 110 is fluidly operatively coupled to the first separator 102, for example via conduit 106, to receive at least a portion of the separated methane from the first separator. The methane reactor 110 is structured and arranged to produce carbon monoxide and hydrogen from the methane received therein. A methanol reactor 116 is fluidly operatively coupled to the methane reactor 110 to receive a portion of the carbon monoxide and a portion of the hydrogen from the methane reactor, for example via conduits 112 and 114, respectively. The methanol reactor 116 is structured and arranged to produce methanol from the carbon monoxide and hydrogen received therein. A methanethiol reactor 232 is fluidly operatively coupled to the first separator 102 to receive hydrogen sulfide from the first separator, for example via a conduit 108, and also is fluidly operatively coupled to methane reactor 110 to receive a portion of the carbon monoxide and a portion of the hydrogen from the methane reactor, for example via conduits 234 and 236, respectively. The methanethiol reactor 232 is structured and arranged to produce methanethiol from the hydrogen sulfide, carbon monoxide, and hydrogen received therein. A dimethyl sulfide reactor 220 to is fluidly operatively coupled to the methanol reactor 116 to receive methanol from the methanol reactor, for example via a conduit 118, and is also fluidly operatively coupled to the methanethiol reactor 232 to receive methanethiol from the methanethiol reactor, for example via a conduit 238. The dimethyl sulfide reactor 220 is structured and arranged to produce dimethyl sulfide from the methanol and methanethiol received therein. The system further includes an injecting mechanism 124 that is structured and arranged to introduce an oil recovery formulation comprising dimethyl sulfide into a petroleum-bearing formation 126, and a producing mechanism 128 that is structured and arranged to produce a fluid comprising petroleum from the petroleum-bearing formation after introduction of the oil recovery formulation into the formation. The injecting mechanism 124 is fluidly operatively coupled to the dimethyl sulfide reactor 220 to receive at least a portion of the dimethyl sulfide from the dimethyl sulfide reactor, for example via conduit 122, where the dimethyl sulfide received in the injecting mechanism is the oil recovery formulation, or is incorporated into the oil recovery formulation, or has been incorporated into the oil recovery formulation. The producing mechanism may produce fluid comprising petroleum from the formation 126 through conduit 130.

Regarding the methanethiol reactor 232, one of ordinary skill in the art, with the benefit of this disclosure, should recognize conventional methods and systems/apparatuses capable of producing methanethiol from the carbon monoxide, hydrogen, and the hydrogen sulfide. For example, a methanethiol reactor may utilize catalyst systems that include WO3/Al2O3 or K2MoO4 at a temperature of from 300° C. to 400° C. for producing methanethiol from carbon monoxide, hydrogen, and hydrogen sulfide.

Regarding the dimethyl sulfide reactor 220, one of ordinary skill in the art, with the benefit of this disclosure, should recognize conventional methods and systems/apparatuses capable of producing dimethyl sulfide from methanol and methanethiol. For example, the dimethyl sulfide reactor 220 may utilize solid acid catalyst systems having moderate acidity, for example La2O3/Al2O3, γ-Al2O3, or WO3/ZrO2 catalyst systems, at a temperature of from 320° C. to 420° C. to produce dimethyl sulfide from methanol and methanethiol. It should be noted that in the foregoing methods and systems, the production of dimethyl sulfide may advantageously include an excess of the stoichiometric amount of methanol used to produce dimethyl sulfide to minimize unreacted methanethiol in the dimethyl sulfide product. In some instances, a recycle loop may be included to mitigate the production of methanethiol in appreciable quantities.

In some embodiments, sour gas from a petroleum-bearing formation may be used to produce dimethyl sulfide. For example, some embodiments may involve producing a fluid from a petroleum-bearing formation, wherein the produced fluid is comprised of a sour gas comprised of methane and hydrogen sulfide; separating methane and separating hydrogen sulfide from the sour gas; producing carbon monoxide and hydrogen from at least a portion of the separated methane; producing methanol from at least a portion of the produced carbon monoxide and the produced hydrogen; and producing dimethyl sulfide from at least a portion of the produced methanol and at least a portion of the separated hydrogen sulfide. In another example, the dimethyl sulfide may be produced from the produced sour gas via methanethiol as described above.

Referring now to FIG. 3 illustrating an exemplary system of the present invention, a system 300 includes a producing mechanism 128 that is structured and arranged to produce a fluid from a petroleum-bearing formation 338, wherein the produced fluid is comprised of petroleum and sour gas, and wherein the sour gas is comprised of methane and hydrogen sulfide. A second separator 340 is fluidly operatively coupled to the producing mechanism 128 to receive the produced fluid from the producing mechanism, for example via conduit 339. The second separator 340 is structured and arranged to separate the sour gas and to separate the petroleum from the produced fluid. The second separator, for example, may be comprised of a conventional liquid-gas separator wherein sour gas is separated from liquid petroleum. Separated liquid petroleum may be provided from second separator 340 to a petroleum storage facility 342 that may be fluidly operatively coupled to the second separator, for example via conduit 341.

The fluid produced from the petroleum-bearing formation may be comprised of dimethyl sulfide and water in addition to petroleum and sour gas. The second separator 340 may be structured and arranged to separate the petroleum, sour gas, dimethyl sulfide, and water components of the fluid produced from the petroleum-bearing formation into individual components. As noted above, the second separator 340 may comprise a conventional liquid-gas separator to separate the sour gas from liquid components of the produced fluid such liquid petroleum, water, and dimethyl sulfide. The second separator 340 may also be comprised of a conventional water-knockout vessel to separate liquid petroleum and dimethyl sulfide from water. The second separator may also be comprised of a conventional distillation or flash column to separate dimethyl sulfide from liquid petroleum. Some embodiments described herein may involve separating the produced fluid stream into its components or component mixtures. For example, some embodiments may involve separating sour gas from the produced fluid. In another example, some embodiments may involve separating sour gas and petroleum from the produced fluid. In yet another example, some embodiments may involve separating sour gas, petroleum, and water from the produced fluid. In another example, some embodiments may involve separating sour gas, petroleum, water, and dimethyl sulfide from the produced fluid. In some instances, the individual components separated from the produced fluid may be stored. In some instances, the individual components separated from the produced fluid may be transported to another location. In some instances, the individual components separated from the produced fluids may be utilized in the systems described herein.

The second separator 340 may be fluidly operatively coupled to a first separator 102 so as to provide the first separator 102 with the sour gas, for example via conduit 343. The first separator 102 may separate the sour gas into methane and hydrogen sulfide, as described above. The system, as illustrated in FIG. 3, includes the methane reactor 110, the methanol reactor 116, and the dimethyl sulfide reactor 120 each appropriately fluidly operatively coupled as described in relation to FIG. 1. As illustrated, the dimethyl sulfide produced by the dimethyl sulfide reactor 120 is passed through a conduit 344.

In some embodiments, the conduit 344 may fluidly operatively couple a petroleum-bearing formation to the dimethyl sulfide reactor 120, where the petroleum-bearing formation may be the petroleum-bearing formation 338 from which the sour gas is produced or another petroleum-bearing formation (e.g., with the inclusion of an injecting mechanism similar to mechanism 124 of FIGS. 1 and 2 in system 300). In some embodiments, a pipeline for transporting the dimethyl sulfide to another location may be fluidly operatively coupled to the dimethyl sulfide reactor 120, for example via conduit 344.

A system according to the present invention may be a hybrid of systems 100 and 300 of FIGS. 1 and 3, respectively. That is, the producing mechanism 128 of FIG. 1 may be the producing mechanism 128 of FIG. 3, and the system may include the conduit 122 and mechanism 124 of FIG. 1 and the conduit 344 of FIG. 3, where conduits 344 and 122 may be fluidly operatively couple the dimethyl sulfide reactor 120 of FIG. 3 with the injecting mechanism 124 of FIG. 1. In this embodiment, at least some of the dimethyl sulfide produced from the sour gas produced from the petroleum-bearing formation would be introduced into the petroleum-bearing formation in an oil recovery formulation for petroleum recovery from the petroleum-bearing formation.

In some embodiments, at least a portion of the petroleum of the produced fluid may be separated from the produced fluid and transported to another location (e.g., via pipeline or vehicular transportation). In some embodiments, the separated petroleum may have a viscosity greater than about 350 cP, which may be of sufficiently high viscosity to make the petroleum difficult to pump or may require significant energy input to pump the petroleum. Therefore, some embodiments may involve mixing a sufficient amount of dimethyl sulfide (or an oil recovery formulation comprising dimethyl sulfide) in the petroleum to reduce the viscosity of the petroleum to no greater than 350 cP, or no greater than 250 cP, or no greater than 150 cP. The dimethyl sulfide used to reduce the viscosity of the petroleum may be at least a portion of the dimethyl sulfide produced from the sour gas, at least a portion of the dimethyl sulfide separated from the fluid produced from the petroleum-bearing formation, or any other dimethyl sulfide source.

Regarding the mechanisms for introducing fluid into and producing fluids from a petroleum-bearing formation, one of ordinary skill in the art, with the benefit of this disclosure, will recognize conventional methods and systems/apparatuses/mechanisms capable of introducing an oil recovery formulation into petroleum-bearing formation and producing a fluid comprising petroleum from petroleum-bearing formation, which may be a single system/apparatus/mechanism (e.g. a single well comprised of injection and production mechanisms) or separate systems/apparatuses/mechanisms (e.g., an injection well in combination with a production well).

The petroleum-bearing formation may, in some embodiments, be a subterranean formation. The subterranean petroleum-bearing formation may be comprised of one or more porous matrix materials selected from the group consisting of a porous mineral matrix, a porous rock matrix, and a combination of a porous mineral matrix and a porous rock matrix, where the porous matrix material may be located beneath an overburden at a depth ranging from 50 meters to 6000 meters, or from 100 meters to 4000 meters, or from 200 meters to 2000 meters under the earth's surface. The subterranean petroleum-bearing formation may be a subsea subterranean formation.

Referring now to FIG. 4 a system 400 for introducing an oil recovery formulation into a subterranean petroleum-bearing formation is shown. The system 400 includes an oil recovery formulation storage facility 401 fluidly operatively coupled to an injection/production facility 403 via conduit 405. The oil recovery formulation storage facility 401 may be fluidly operatively coupled to the dimethyl sulfide reactors of FIGS. 1-3 as described herein to receive dimethyl sulfide from a dimethyl sulfide reactor. The injection/production facility 403 may be fluidly operatively coupled to a well 407 to provide the oil recovery formulation comprising at least 75 mol % dimethyl sulfide to the well. The well may be located extending from the injection/production facility 403 into a petroleum-bearing formation 409 comprised of, for example, one or more formation portions 411, 413, and 415 formed of porous material matrices, such as described above, located beneath an overburden 417. As shown by the down arrow in well 407, the oil recovery formulation may flow from the injection/production facility 403 through the well to be introduced into the formation 409, for example in formation portion 413, where the injection/production facility 403 and the well 407, or the well 407 itself, include(s) an injecting mechanism for introducing the oil recovery formulation into the formation 409. The injecting mechanism for introducing the oil recovery formulation into the formation 409 may be comprised of a pump 410 for delivering the oil recovery formulation to perforations or openings in the well through which the oil recovery formulation may be injected into the formation.

One of ordinary skill in the art, with the benefit of this disclosure, should recognize the conditions under which the oil recovery formulation may be introduced into the formation. For example, to mitigate fracturing the formation, the oil recovery formulation may be injected into the formation at a pressure from the instantaneous pressure in the formation up to, but not including, the fracture pressure of the formation.

As the oil recovery formulation is introduced into the formation 409, the oil recovery formulation spreads into the formation as shown by arrows 419. Upon introduction to the formation 409, the oil recovery formulation contacts and forms a mixture with a portion of the petroleum in the formation. The oil recovery formulation is miscible with the petroleum in the formation, where the oil recovery formulation mobilizes at least a portion of the petroleum in the formation upon mixing with the petroleum. In some instances to enhance mobilization of the petroleum, the oil recovery formulation may be left to soak in the formation after introduction of the oil recovery formulation into the formation to mix with and mobilize the petroleum in the formation. The oil recovery formulation may be left to soak in the formation for a period of time of from 1 hour to 15 days, preferably from 5 hours to 50 hours.

Referring now to FIG. 5, subsequent to the introduction of the oil recovery formulation into the formation 409 and after the soaking period, a fluid comprising petroleum and optionally sour gas, dimethyl sulfide, and water as described above may be recovered and produced from the formation 409 as shown by arrows 421 and produced back up the well 407 to the injection/production facility 403. The producing mechanism for recovering and producing the produced fluid from the formation 409 may be comprised of a pump 412, which may be located in the injection/production facility 403 and/or within the well 407, and which may draw the produced fluid from the formation to deliver the produced fluid to the facility 403.

Alternatively, the mechanism for recovering and producing the fluid from the formation 409 may include a compressor 414. The compressor 414 may be fluidly operatively coupled to a gas storage tank 429 by conduit 416, and may compress gas from the gas storage tank for injection into the formation 409 through the well 407. The compressor may compress the gas to a pressure sufficient to drive production of the produced fluid from the formation via the well 407, where the appropriate pressure can be determined by conventional methods known to those skilled in the art. The compressed gas may be injected into the formation from a different position on the well 407 than the well position from which the fluid is produced from the formation, for example, the compressed gas may be injected into the formation at formation portion 411 while the fluid is produced from the formation at formation portion 413.

The injection/production facility 403 may include a separation unit 423, which may correspond to the second separator 340 as shown in FIG. 3. The separation unit 423 may be comprised of a conventional liquid-gas separator for separating sour gas from the petroleum, dimethyl sulfide, and water; a conventional hydrocarbon-water separator for separating water from petroleum and dimethyl sulfide, and a conventional distillation column for separating dimethyl sulfide from the petroleum.

The separated petroleum may be provided from the separation unit 423 of the injection/production facility 403 to a liquid petroleum storage tank 425, which may be fluidly operatively coupled to the separation unit of the injection/production facility by conduit 427. The separated sour gas may be provided from the separation unit 423 of the injection/production facility 403 to the gas storage tank 429, which may be fluidly operatively coupled to the separation unit of the injection/production facility by conduit 431. The separated produced dimethyl sulfide may be provided from the separation unit 423 of the injection/production facility to the oil recovery formulation storage facility 401, which may be fluidly operatively coupled to the separation unit of the injection/production facility by conduit 433. Alternatively, the separated produced dimethyl sulfide may be provided from the separation unit 423 of the injection/production facility 403 to the injection mechanism 410 for reinjection into the formation 409, where the separation unit 423 may be fluidly operatively coupled to the injection mechanism 410 via conduit 418 to provide the separated produced dimethyl sulfide from the separation unit 423 to the injection mechanism 410. Separated water may be provided from the separation unit 423 of the injection/production facility 403 to a water tank 435, which may be fluidly operatively coupled to the separation unit of the injection/production facility by conduit 437. The water tank 435 may be fluidly operatively coupled to the injection mechanism 410 by conduit 439 for re-injection of water produced from the formation back into the formation.

One of ordinary skill in the art, with the benefit of this disclosure, should recognize modifications to the mechanisms for introducing an oil recovery formulation into and producing the produced fluid from a subterranean formation. For example, a system of two or more wells may be utilized where at least one well is an injection well and at least one well is a production well. For example, the injecting mechanism for introducing an oil recovery formulation comprised of at least 75 mol % dimethyl sulfide into a subterranean formation may be at a first well extending into the subterranean formation, and the producing mechanism for producing the fluid from a subterranean formation may be at a second well extending into the subterranean formation.

In some embodiments, the systems described herein may be modified to accommodate an array of wells. For example, two or more injecting mechanisms for introducing an oil recovery formulation comprising dimethyl sulfide into a petroleum-bearing formation may be fluidly operatively coupled to the dimethyl sulfide reactor described herein so as to provide an oil recovery formulation to the two or more injecting mechanisms. Two or more producing mechanisms for producing the fluid from a petroleum-bearing formation may be fluidly operatively coupled to the second separator described herein for providing a sour gas stream thereto. Some embodiments may be a combination of the foregoing.

In some instances, the array may include wells configured to introduce the oil recovery formulation into the petroleum-bearing formation and to produce the fluid from the petroleum-bearing formation. In some instances, the array may include a first group of wells configured to introduce the oil recovery formulation into the petroleum-bearing formation and a second group of wells configured to produce the fluid from the petroleum-bearing formation.

Referring now to FIG. 6 an exemplary array 600 comprising the systems described herein is shown. Array 600 includes a first well group 602 (denoted by horizontal lines), a second well group 604 (denoted by diagonal lines), and a system 606 that includes at least the second separator, the dimethyl sulfide reactor, and the corresponding other components therebetween as described, for example, in FIGS. 1-3. In some instances, the first well group 602 may include a plurality of production wells (e.g., mechanisms for producing the fluid from a petroleum-bearing formation) that may individually be fluidly operatively coupled to the second separator described herein for providing sour gas thereto, and the second well group 604 may include a plurality of injection wells (e.g., mechanisms for introducing an oil recovery formulation comprising dimethyl sulfide into a petroleum-bearing formation) that may individually be fluidly operatively coupled to the dimethyl sulfide reactor described herein so as to provide an oil recovery formation comprising dimethyl sulfide to the injection wells.

In some embodiments, the array of wells 600 may have from about 10 to about 1000 wells, for example from about 5 to about 500 wells in the first well group 602, and from about 5 to about 500 wells in the second well group 604.

In some embodiments, the array of wells 600 may include about 1 system 606 for each well to 50 wells.

One of ordinary skill in the art, with the benefit of this disclosure, should recognize the appropriate distance between individual wells and between wells and a system 606.

To facilitate a better understanding of the present invention, the following examples of preferred or representative embodiments are given. In no way should the following examples be read to limit, or to define, the scope of the invention.

EXAMPLES DMS as an EOR Agent Example 1

The quality of dimethyl sulfide as an oil recovery agent based on the miscibility of dimethyl sulfide with a crude oil relative to other compounds was evaluated. The miscibility of dimethyl sulfide, ethyl acetate, o-xylene, carbon disulfide, chloroform, dichloromethane, tetrahydrofuran, and pentane solvents with Muskeg River mined oil sands was measured by extracting the oil sands with the solvents at 10° C. and at 30° C. to determine the fraction of hydrocarbons extracted from the oil sands by the solvents. The bitumen content of the Muskeg River mined oil sands was measured at 11 wt. % as an average of bitumen extraction yield values for solvents known to effectively extract substantially all of bitumen from oil sands—in particular chloroform, dichloromethane, o-xylene, tetrahydrofuran, and carbon disulfide. One oil sands sample per solvent per extraction temperature was prepared for extraction, where the solvents used for extraction of the oil sands samples were dimethyl sulfide, ethyl acetate, o-xylene, carbon disulfide, chloroform, dichloromethane, tetrahydrofuran, and pentane. Each oil sands sample was weighed and placed in a cellulose extraction thimble that was placed on a porous polyethylene support disk in a jacketed glass cylinder with a drip rate control valve. Each oil sands sample was then extracted with a selected solvent at a selected temperature (10° C. or 30° C.) in a cyclic contact and drain experiment, where the contact time ranged from 15 to 60 minutes. Fresh contacting solvent was applied and the cyclic extraction repeated until the fluid drained from the apparatus became pale brown in color.

The extracted fluids were stripped of solvent using a rotary evaporator and thereafter vacuum dried to remove residual solvent. The recovered bitumen samples all had residual solvent present in the range of from 3 wt. % to 7 wt. %. The residual solids and extraction thimble were air dried, weighed, and then vacuum dried. Essentially no weight loss was observed upon vacuum drying the residual solids, indicating that the solids did not retain either extraction solvent or easily mobilized water. Collectively, the weight of the solid or sample and thimble recovered after extraction plus the quantity of bitumen recovered after extraction divided by the weight of the initial oil sands sample plus the thimble provide the mass closure for the extractions. The calculated percent mass closure of the samples was slightly high because the recovered bitumen values were not corrected for the 3 wt. % to 7 wt. % residual solvent. The extraction experiment results are summarized in Table 1.

TABLE 1 Summary of Extraction Experiments of Bituminous Oil Sands with Various Fluids Input Output Experimental Temperature, Solids Solids Weight Recovered Weight Extraction Fluid C. weight, g weight, g Change, g Bitumen, g Closure, % Carbon Disulfide 30 151.1 134.74 16.4 16.43 100.0 Carbon Disulfide 10 151.4 134.62 16.8 16.62 99.9 Chloroform 30 153.7 134.3 19.4 18.62 99.5 Chloroform 10 156.2 137.5 18.7 17.85 99.5 Dichloromethane 30 155.8 138.18 17.7 16.30 99.1 Dichloromethane 10 155.2 136.33 18.9 17.66 99.2 o-Xylene 30 156.1 136.58 19.5 17.37 98.6 o-Xylene 10 154.0 136.66 17.3 17.36 100.0 Tetrahydrofuran 30 154.7 136.73 18.0 17.67 99.8 Tetrahydrofuran 10 154.7 136.98 17.7 16.72 99.4 Ethyl Acetate 30 153.5 135.81 17.7 11.46 96.0 Ethyl Acetate 10 155.7 144.51 11.2 10.32 99.4 Pentane 30 154.0 139.11 14.9 13.49 99.1 Pentane 10 152.7 138.65 14.1 13.03 99.3 Dimethyl Sulfide 30 154.2 137.52 16.7 16.29 99.7 Dimethyl Sulfide 10 151.7 134.77 16.9 16.55 99.7

FIG. 7 provides a graph plotting the weight percent yield of extracted bitumen as a function of the extraction fluid at 30° C. applied with a correction factor for residual extraction fluid in the recovered bitumen, and FIG. 8 provides a similar graph for extraction at 10° C. without a correction factor. FIGS. 7 and 8 and Table 1 show that dimethyl sulfide is comparable for recovering bitumen from an oil sand material with the best known fluids for recovering bitumen from an oil sand material—o-xylene, chloroform, carbon disulfide, dichloromethane, and tetrahydrofuran—and is significantly better than pentane and ethyl acetate.

The bitumen samples extracted at 30° C. from each oil sands sample were evaluated by SARA analysis to determine the saturates, aromatics, resins, and asphaltenes composition of the bitumen samples extracted by each solvent. The results are shown in Table 2.

TABLE 2 SARA Analysis of Extracted Bitumen Samples as a Function of Extraction Fluid Oil Composition Normalized Weight Percent Extraction Fluid Saturates Aromatics Resins Asphaltenes Ethyl Acetate 21.30 53.72 22.92 2.05 Pentane 22.74 54.16 22.74 0.36 Dichloromethane 15.79 44.77 24.98 14.45 Dimethyl Sulfide 15.49 47.07 24.25 13.19 Carbon Disulfide 18.77 41.89 25.49 13.85 o-Xylene 17.37 46.39 22.28 13.96 Tetrahydrofuran 16.11 45.24 24.38 14.27 Chloroform 15.64 43.56 25.94 14.86

The SARA analysis showed that pentane and ethyl acetate were much less effective for extraction of asphaltenes from oil sands than are the known highly effective bitumen extraction fluids dichloromethane, carbon disulfide, o-xylene, tetrahydrofuran, and chloroform. The SARA analysis also showed that dimethyl sulfide has excellent miscibility properties for even the most difficult hydrocarbons—asphaltenes.

The data showed that dimethyl sulfide is generally as good as the recognized very good bitumen extraction fluids for recovery of bitumen from oil sands, and is highly compatible with saturates, aromatics, resins, and asphaltenes.

DMS as an EOR Agent Example 2

The quality of dimethyl sulfide as an oil recovery agent based on the crude oil viscosity lowering properties of dimethyl sulfide was evaluated. Three crude oils having widely disparate viscosity characteristics—an African Waxy crude, a Middle Eastern asphaltic crude, and a Canadian asphaltic crude—were blended with dimethyl sulfide. Some properties of the three crudes are provided in Table 3.

TABLE 3 Crude Oil Properties Middle African Eastern Canadian Waxy Asphaltic Asphaltic crude crude Crude Hydrogen (wt. %) 13.21 11.62 10.1 Carbon (wt. %) 86.46 86.55 82 Oxygen (wt. %) na na 0.62 Nitrogen (wt. %) 0.166 0.184 0.37 Sulfur (wt. %) 0.124 1.61 6.69 Nickel (ppm wt.) 32 14.2 70 Vanadium (ppm wt.) 1 11.2 205 microcarbon residue (wt. %) na 8.50 12.5 C₅ Asphaltenes (wt. %) <0.1 na 16.2 C₇ Asphaltenes (wt. %) <0.1 na 10.9 Density (g/ml) (15.6° C.) 0.88 0.9509 1.01 API Gravity (15.6° C.) 28.1 17.3 8.5 Water (Karl Fisher Titration) (wt. %) 1.65 <0.1 <0.1 TAN-E (ASTM D664) (mg KOH/g) 1.34 4.5 3.91 Volatiles Removed by Topping, wt % 21.6 0 0 Saturates in Topped Fluid, wt. % 60.4 41.7 12.7 Aromatics in Topped Fluid, wt. % 31.0 40.5 57.1 Resin in Topped Fluid, wt. % 8.5 14.5 17.1 Asphaltenes in Topped Fluid, wt. % 0.1 3.4 13.1 Boiling Range Distribution Initial Boiling Point-204° C. (wt. %) 8.5 3.0 0 204° C. (400° F.)-260° C. (wt. %) 9.5 5.8 1.0 260° C. (500° F.)-343° C. (wt. %) 16.0 14.0 14.0 343° C. (650° F.)-538° C. (wt. %) 39.5 42.9 38.0 >538° C. (wt. %) 26.5 34.3 47.0

A control sample of each crude was prepared containing no dimethyl sulfide, and samples of each crude were prepared and blended with dimethyl sulfide to prepare crude samples containing increasing concentrations of dimethyl sulfide. Each sample of each of the crudes was heated to 60° C. to dissolve any waxes therein and to permit weighing of a homogeneous liquid, weighed, allowed to cool overnight, then blended with a selected quantity of dimethyl sulfide. The samples of the crude/dimethyl sulfide blend were then heated to 60° C. and mixed to ensure homogeneous blending of the dimethyl sulfide in the samples. Absolute (dynamic) viscosity measurements of each of the samples were taken using a rheometer and a closed cup sensor assembly. Viscosity measurements of each of the samples of the West African waxy crude and the Middle Eastern asphaltic crude were taken at 20° C., 40° C., 60° C., 80° C., and then again at 20° C. after cooling from 80° C., where the second measurement at 20° C. is taken to measure the viscosity without the presence of waxes since wax formation occurs slowly enough to permit viscosity measurement at 20° C. without the presence of wax. Viscosity measurements of each of the samples of the Canadian asphaltic crude were taken at 5° C., 10° C., 20° C., 40° C., 60° C., 80° C., The measured viscosities for each of the crudes are shown in Tables 4, 5, and 6 below.

TABLE 4 Viscosity (mPa s) of West African Waxy Crude vs. Temperature at Various levels of Dimethyl Sulfide Diluent DMS, wt. % 20° C. 40° C. 60° C. 80° C. 20° C. 0.00 128.8 34.94 15.84 9.59 114.4 1.21 125.8 30.94 14.66 8.92 100.1 2.48 122.3 30.53 13.66 8.44 89.23 5.03 78.37 20.24 10.45 6.55 55.21 7.60 60.92 17.08 9.29 6.09 40.89 9.95 44.70 13.03 7.58 5.04 30.61 15.13 23.96 8.32 4.97 3.38 17.64 19.30 15.26 6.25 4.05 2.92 12.06

TABLE 5 Viscosity (mPa s) of Middle Eastern Asphaltic Crude vs. Temperature at Various levels of Dimethyl Sulfide Diluent DMS, wt. % 20° C. 40° C. 60° C. 80° C. 20° C. 0.00 2936.3 502.6 143.6 56.6 2922.7 1.3 1733.8 334.5 106.7 44.6 1624.8 2.6 1026.6 219.9 76.5 34.3 881.1 5.3 496.5 134.2 52.2 25.5 503.5 7.6 288.0 89.4 37.4 19.3 290.0 10.1 150.0 52.4 24.5 13.5 150.5 15.2 59.4 25.2 13.6 8.2 60.7 20.1 29.9 14.8 8.7 5.7 31.0

TABLE 6 Viscosity (mPa s) of Topped Canadian Asphaltic Crude vs. Temperature at Various levels of Dimethyl Sulfide Diluent DMS, wt. % 5° C. 10° C. 20° C. 40° C. 60° C. 80° C. 0.00 579804 28340 3403 732 1.43 212525 14721 2209 538 2.07 134880 10523 1747 427 4.87 28720 3235 985 328 8.01 5799 982 275 106 9.80 2760 571 173 73 14.81 1794 1155 548 159 64 32 19.78 188 69 33 19 29.88 113 81 51 22 13 8 39.61 23 20 14 8 6 4

FIGS. 9, 10, and 11 show plots of Log [Log(Viscosity)] v. Log [Temperature ° K] derived from the measured viscosities in Tables 4, 5, and 6, respectively, illustrating the effect of increasing concentrations of dimethyl sulfide in lowering the viscosity of the crude samples.

The measured viscosities and the plots show that dimethyl sulfide is effective for significantly lowering the viscosity of a crude oil over a wide range of initial crude oil viscosities.

DMS as an EOR Agent Example 3

Incremental recovery of oil from a formation core using an oil recovery formulation consisting of dimethyl sulfide following oil recovery from the core by water-flooding was measured to evaluate the effectiveness of DMS as a tertiary oil recovery agent.

Two 5.02 cm long Berea sandstone cores with a core diameter of 3.78 cm and a permeability between 925 and 1325 mD were saturated with a brine having a composition as set forth in Table 7.

TABLE 7 Brine Composition Chemical component CaCl₂ MgCl₂ KCl NaCl Na₂SO₄ NaHCO₃ Concentration 0.386 0.523 1.478 28.311 0.072 0.181 (kppm)

After saturation of the cores with brine, the brine was displaced by a Middle Eastern Asphaltic crude oil having the characteristics as set forth above in Table 3 to saturate the cores with oil.

Oil was recovered from each oil saturated core by the addition of brine to the core under pressure and by subsequent addition of DMS to the core under pressure. Each core was treated as follows to determine the amount of oil recovered from the core by addition of brine followed by addition of DMS. Oil was initially displaced from the core by addition of brine to the core under pressure. A confining pressure of 1 MPa was applied to the core during addition of the brine, and the flow rate of brine to the core was set at 0.05 ml/min. The core was maintained at a temperature of 50° C. during displacement of oil from the core with brine. Oil was produced and collected from the core during the displacement of oil from the core with brine until no further oil production was observed (24 hours). After no further oil was displaced from the core by the brine, oil was displaced from the core by addition of DMS to the core under pressure. DMS was added to the core at a flow rate of 0.05 ml/min for a period of 32 hours for the first core and for a period of 15 hours for the second core. Oil displaced from the core during the addition of DMS to the core was collected separately from the oil displaced by the addition of brine to the core.

The oil samples collected from each core by brine displacement and by DMS displacement were isolated from water by extraction with dichloromethane, and the separated organic layer was dried over sodium sulfate. After evaporation of volatiles from the separated, dried organic layer of each oil sample, the amount of oil displaced by brine addition to a core and the amount of oil displaced by DMS addition to the core were weighed. Volatiles were also evaporated from a sample of the Middle Eastern asphaltic oil to be able to correct for loss of light-end compounds during evaporation. Table 8 shows the amount of oil produced from each core by brine displacement followed by DMS displacement.

TABLE 8 Oil produced Oil produced Oil produced Brine dis- Oil produced DMS dis- Brine dis- placement DMS dis- placement placement (of % oil ini- placement (of % oil ini- (ml) tially in core) (ml) tially in core) Core 1 4.9 45 3.5 32 Core 2 5.0 45 3.3 30

As shown in Table 8, DMS is quite effective for recovering an incremental quantity of oil from a formation core after recovery of oil from the core by waterflooding with a brine solution—recovering approximately 60% of the oil remaining in the core after the waterflood.

Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope of the present invention. The invention illustratively disclosed herein suitably may be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. 

What is claimed:
 1. A method comprising: separating methane and separating hydrogen sulfide from a sour gas comprised of methane and hydrogen sulfide; producing carbon monoxide and hydrogen from at least a portion of the separated methane; producing methanol from at least a portion of the produced carbon monoxide and at least a portion of the produced hydrogen; producing a dimethyl sulfide from at least a portion of the produced methanol and at least a portion of the separated hydrogen sulfide; producing an oil recovery formulation that comprises at least 75 mol % dimethyl sulfide from at least a portion of the produced dimethyl sulfide; introducing the oil recovery formulation into a petroleum-bearing formation comprising petroleum; contacting the oil recovery formulation with petroleum in the petroleum-bearing formation; and subsequent to contacting the oil recovery formulation with petroleum in the petroleum-bearing formation, producing a fluid from the petroleum-bearing formation, wherein the produced fluid comprises at least a portion of the petroleum from the petroleum-bearing formation.
 2. The method of claim 1, wherein the produced fluid further comprises sour gas.
 3. The method of claim 2 further comprising: separating petroleum and separating sour gas from the produced fluid, wherein at least a portion of the separated sour gas is a portion of the sour gas separated into methane and hydrogen sulfide.
 4. The method of claim 1, wherein the produced fluid further comprises dimethyl sulfide.
 5. The method of claim 4 further comprising: separating petroleum and separating dimethyl sulfide from the produced fluid; and producing at least a portion of the oil recovery formulation with the dimethyl sulfide separated from the produced fluid,
 6. The method of claim 1 further comprising: separating petroleum from the produced fluid, wherein the petroleum has a viscosity greater than 350 cP; and mixing an amount of dimethyl sulfide with the petroleum separated from the produced fluid effective to reduce the viscosity of the mixture to less than 350 cP.
 7. The method of claim 1, wherein the dimethyl sulfide is produced at a well-site where the oil recovery formulation is introduced into the petroleum-bearing formation.
 8. The method of claim 1, wherein the oil recovery formulation is introduced into the petroleum-bearing formation by injection via a first well extending into the petroleum-bearing formation.
 9. The method of claim 8, wherein the fluid comprising petroleum is produced from the petroleum-bearing formation via the first well.
 10. The method of claim 8, wherein the fluid comprising petroleum is produced from the petroleum-bearing formation via a second well extending into the petroleum-bearing formation.
 11. The method of claim 1, wherein the petroleum-bearing formation is a subterranean formation located at a depth of at least 75 meters below the surface of the earth.
 12. A system comprising: a first separator structured and arranged to receive a sour gas comprised of methane and hydrogen sulfide, wherein the first separator is structured and arranged to separate methane and hydrogen sulfide from the sour gas; a methane reactor fluidly operatively coupled to the first separator to receive at least a portion of the separated methane from the first separator, wherein the methane reactor is structured and arranged to produce carbon monoxide and hydrogen from the methane received therein; a methanol reactor fluidly operatively coupled to the methane reactor to receive carbon monoxide and hydrogen from the methane reactor, wherein the methanol reactor is structured and arranged to produce methanol from the carbon monoxide and hydrogen received therein; a dimethyl sulfide reactor fluidly operatively coupled to the methanol reactor to receive methanol from the methanol reactor and fluidly operatively coupled to the first separator to receive hydrogen sulfide from the first separator, wherein the dimethyl sulfide reactor is structured and arranged to produce dimethyl sulfide from the methanol and the hydrogen sulfide received therein; an injecting mechanism fluidly operatively coupled to the dimethyl sulfide reactor to receive dimethyl sulfide from the dimethyl sulfide reactor, wherein the injecting mechanism is structured and arranged to introduce an oil recovery formulation comprised of dimethyl sulfide received from the dimethyl sulfide reactor into a petroleum-bearing formation; a producing mechanism that is structured and arranged to produce a fluid comprised of petroleum from the petroleum-bearing formation.
 13. The system of claim 12, wherein the petroleum-bearing formation further comprises sour gas comprised of methane and hydrogen sulfide, and wherein the produced fluid further comprises sour gas comprised of methane and hydrogen sulfide.
 14. The system of claim 13 further comprising: a second separator fluidly operatively coupled to the producing mechanism to receive the produced fluid from the producing mechanism, wherein the second separator is structured and arranged to separate the produced fluid into sour gas and petroleum; wherein the second separator is fluidly operatively coupled to the first separator and at least a portion of the sour gas separated in the second separator is provided to the first separator.
 15. The system of claim 14, wherein the produced fluid further comprises dimethyl sulfide, the second separator is structured and arranged to separate dimethyl sulfide from the produced fluid, the second separator is fluidly operatively coupled to the injecting mechanism to provide the separated dimethyl sulfide to the injecting mechanism, and wherein the injecting mechanism is structured and arranged to introduce the separated dimethyl sulfide into the petroleum-bearing formation.
 16. The system of claim 12, wherein the injecting mechanism is located at a first well extending into the petroleum-bearing formation.
 17. The system of claim 16, wherein the producing mechanism is located at the first well extending into the petroleum-bearing formation.
 18. The system of claim 16, wherein the producing mechanism is located at a second well extending into the petroleum-bearing formation. 